Note: Descriptions are shown in the official language in which they were submitted.
CA 02929318 2016-05-09
1 "MIXED FORM TUBULAR CENTRALIZERS AND METHOD OF USE"
2
3 FIELD
4
Embodiments disclosed herein relate to apparatus for centralizing a
tubular in a wellbore and more particularly, to centralizing a tubular drill
string in a
6
wellbore. Embodiments disclosed herein also relate to a method for replacing
worn
7 components/parts of the apparatus.
8
9 BACKGROUND
Centralizers are known for positioning tubulars, such as casing, drill
11 pipes,
rod strings and the like, within wellbores to minimize wear between the
12 tubular
and the wellbore walls in the case of an openhole application, or between
13 the
tubular and the casing walls in a cased wellbore, regardless the orientation
of
14 the
wellbore. Without a centralizer, wear may be enhanced in horizontal wellbores
particularly at the heel or deviated portion of the wellbore where directional
changes
16 would
otherwise cause the tubular to engage the casing. Further, without a
17
centralizer, grinding of the casing may occur when portions of the tubular,
such as
18 the
drill pipe tool joints, are hard-faced with stiff material such as tungsten
carbide.
19 Efforts
are made to make the hard-facing as smooth as possible so as to minimize
the casing wear but since the drill pipe rotates it is inevitable that drill
pipe tool joints
21 will wear against the casing.
22
Generally, the centralizer engages the tubular and acts to space the
23 tubular
from either the wellbore walls or the casing. Casing centralizers are
1
CA 02929318 2016-05-09
1 generally one piece and slide over the casing. Tubulars, such as drill
pipe, have tool
2 ends formed thereon and therefore drill pipe centralizers must be clamped
over the
3 tubular and secured thereon.
4 One such centralizer available from Hawkeye Industries Inc. of
Edmonton, Alberta, Canada comprises a discontinuous, molded urethane, tubular
6 body which is sufficiently flexible to be installed about a tubing
string. The tubular
7 body has molded fins extending radially outwardly therefrom to space the
tubing
8 string from the casing or wellbore walls. The centralizer is secured
about the tubing
9 string using a stainless steel band clamp. When the fins on the
centralizer body
have worn such that they no longer provide sufficient offset to space the
tubular
11 from the wellbore or casing walls, the centralizers are discarded and
replaced.
12 Another tubing centralizer is available from Western Well Tool
Ltd., of
13 Houston Texas, USA. A tubular body of the centralizer comprises a
plurality of
14 hinged segments which are pinned together to encircle the tubular.
Opposing end
collars abut uphole and downhole ends of the tubular body for positioning the
16 centralizer along a length of the tubular. The end or thrust collars,
generally
17 comprise two arcuate segments which are bolted together about the
tubular to form
18 the thrust collars. The thrust collars sandwich the tubular body
therebetween in the
19 axial direction. The bolts are typically high tensile steel bolts.
Applicant understands
that the hinged segments and the pins which connect the segments to form the
21 body are prone to failure with repeated use. Failure of centralizers can
be costly,
22 particularly if portions of the centralizer fall into the wellbore and
disrupt operations
23 therein.
2
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1 Yet
another example of a prior art tubing centralizer is the RotoTECO
2
centralizer available from Tercel Oilfield Products, Dubai, UAE. The RotoTECO
3
centralizer comprises a freely rotating outer sleeve positioned over an
internal pipe
4 sleeve.
The sleeves are made of a composite material such as a self-lubricating
polymer with a low coefficient of friction and appear to comprise at least two
"clam-
6 shell"
halves which are pinned together in order to be positioned over the tubing.
7 Upper
and lower retaining clamps are bolted about the tubing string for retaining
the
8 sleeves
thereon in the axial direction. When the outer sleeve is worn such that it no
9 longer
provides sufficient standoff to space the tubular from the wellbore or casing
walls, at least the outer sleeve must be discarded and replaced.
11 In
another aspect, there are competing objectives for centralizers in
12
openholes and cased wellbore environments. While the centralizers must provide
13
adequate standoff, centralizers running against casing are expected to
minimize
14 wear of
the casing string. The nature of such centralizers is that the resilient
nature
thereof renders the softer portion of the centralizer vulnerable to wear and
failure in
16 openhole scenarios.
17 There
is interest in the industry for a simple, efficient tubing centralizer
18 and
methodology for drilling that considers the environment for cased wellbores
and
19 open portion of horizontal wells.
21 SUMMARY
22
Embodiments disclosed herein are related to tubing centralizers and,
23 more
particularly, to drill pipe centralizers. The term tubular is used herein in a
3
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1 broad sense to mean a tubular pipe, drill pipe, tubular strings, a casing
or the like.
2 The tubular centralizers have a simple construction and have reduced
number of
3 connectors, thereby minimizing the risk of failure and setup/assembly
time. The
4 structure of the tubular centralizer is also such that it enables
replacement of only
the component contacting the wellbore or casing walls and deteriorated due to
6 constant contact. End collars of the centralizer retain other components
of the
7 centralizer both radially and axially about the tubular.
8 Herein, two forms of centralizers are contemplated, both of which
9 utilize a metal outer support body, a resilient inner sleeve and
retaining end collars
according to embodiments described herein. The form of the centralizer is
matched
11 with the wellbore environment. The centralizers have a metal or hard-
faced metal
12 protrusions for use in openhole wellbores and resilient protrusions for
use in cased
13 wellbores. In the horizontal well context, the openhole wellbore is
typically the
14 horizontal portion extending out of the cased portion from the heel
portion to the end,
usually called the toe section. Openhole is much more abrasive and destructive
to
16 centralizers than is the inside of the smooth casing. Centralizers
quickly degrade
17 when they exit the casing and end up in openhole. Further, the slip-
slide nature of
18 bent sub drilling operations exacerbates the damage to centralizers.
19 In drilling operations, one can extend the wellbore using
resilient
centralizers on the drill string to protect the previously cased portion of
the wellbore
21 at least until a new portion of the horizontal portion is drilled, One
can coordinate a
22 trip with a bit change, the drill string is tripped out and a downhole
length of the drill
23 string that will be exposed to the openhole is fit with metal
centralizers and resilient
4
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1 centralizers for the portion of the drill string that is remaining, for
the most part, in
2 the casing. Of course, as one drills forward, some of the resilient
centralizers in the
3 casing will exit the cased portion and end up in the openhole and be
subject to wear.
4 However, significant operational advantages are realized with metal
centralizers for
that majority of the drill string portion that spends most of its moving in
openhole.
6 Accordingly in one aspect there is provided a centralizer for
installing
7 about a joint of tubular within a wellbore. The centralizer comprises a
resilient inner
8 sleeve having a central bore formed therethrough for receiving the
tubular therein
9 and an outer surface. The centralizer further comprises a tubular outer
support body
having opposing end portions and a central bore formed therethrough for
receiving
11 the inner sleeve's outer surface. Three or more protruding members are
spaced
12 circumferentially about the centralizer and extend radially outwardly
for spacing the
13 tubular from the wellbore. The inner sleeve extends longitudinally
beneath the
14 support body. The centralizer further comprises a pair of annular end
collars for
retaining the support body and inner sleeve in the radial direction about the
tubular
16 and axially thereto. Each end collar has a collar bore for securing to
the tubular and
17 for securing to an opposing end portion of the support body.
18 In an embodiment, the three or more protruding members extend
19 radially outwardly from the support body. The inner sleeve can extend
contiguously
under the support body between the end collars. The inner sleeve can further
21 comprise three or more protruding resilient members corresponding with
the three
22 or more protruding members of the support body, providing radial support
therefor.
5
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1 Each of
the support body's protruding members have a radial tip for engaging the
2 wellbore, each tip further comprising hard-facing thereon.
3 In
another embodiment, the three or more protruding members are
4
resilient members contiguous with and extending radially outwardly from the
inner
sleeve. Further, the support body has windows formed therein which correspond
6 with
the protruding members. When the inner sleeve is retained between the
7 support
body and the tubular, the protruding members project through the windows
8 with
the balance of the inner sleeve extending longitudinally beneath the support
9 body.
In embodiments, the inner sleeve comprises two or more
11
circumferentially arcuate inner sleeve segments retained about the tubular by
the
12 support
body. In another embodiment, the inner sleeve comprises three or more
13 arcuate
inner sleeve segments retained about the tubular by the support body.
14
Further, the support body can be provided as two or more support body segments
and the two or more support body segments are retained about the inner sleeve
by
16 the end collars.
17
Accordingly in another aspect there is provided a centralizer for
18
installing about a joint of tubular within a wellbore. The centralizer
comprises a
19
resilient inner sleeve having a central bore formed therethrough for receiving
the
tubular therein and an outer surface from which three or more protruding
members
21 extend
radially outwardly. The three or more protruding members are spaced
22
circumferentially about the inner sleeve for spacing the tubular from the
wellbore.
23 The
centralizer further comprises a tubular outer support body having opposing end
6
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1 portions and a central bore formed therethrough for receiving the inner
sleeve's
2 outer surface. The support body has windows formed therein which
correspond with
3 the protruding members. When the inner sleeve is retained between the
support
4 body and the tubular, the protruding members project through the windows
with the
balance of the inner sleeve extending longitudinally beneath the support body.
The
6 centralizer further comprises a pair of annular end collars for retaining
the outer
7 body and inner sleeve in the radial direction about the tubular and
axially thereto.
8 Each end collar has a collar bore for securing to the tubular and for
securing to an
9 opposing end portion of the support body.
Accordingly in another aspect a method for removing and replacing
11 worn components of a centralizer is provided. The centralizer comprises
two or
12 more arcuate inner sleeve segments retained about the tubular by two or
more
13 support body segments. The two or more support body segments are
retained both
14 axially and radially about the inner sleeve segments by the end collar.
The method
comprises disengaging at least one of the pair of end collars and removing at
least
16 one of the two or more support body segments for accessing the two or
more inner
17 sleeve segments having one or more worn protruding members. At least one
inner
18 sleeve segment with the worn protruding members is removed. Each of the
19 removed inner sleeve segments is replaced with a replacement inner
sleeve
segment with its protruding members extending through corresponding support
21 body windows of the at least one removed support body segment. The
method
22 further comprises re-installing the outer body segments and replacement
inner
7
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1 sleeve
segments about the tubular and securing the at least one end collar about
2 opposing ends of the support body.
3 The
inner sleeve and the support body may comprise multiple
4 segments.
In one embodiment, the inner sleeve comprises two or more arcuate
6 inner sleeve segments retained about the tubular by the support body.
7 In
another embodiment, the inner sleeve comprises three or more
8 arcuate inner sleeve segments retained about the tubular by the support
body.
9 In
another embodiment, the support body comprises two or more
support body segments and the two or more support body segments are retained
11 about the inner sleeve by the end collars.
12 In
another embodiment, the inner sleeve comprises two or more
13 arcuate
inner sleeve segments and the support body comprises two or more
14 support
body segments. The two or more inner sleeve segments are retained about
the tubular by the two or more support body segments. The two or more support
16 body segments are retained about the inner sleeve by the end collars.
17 In
another embodiment, the inner sleeve comprises three or more
18 arcuate
inner sleeve segments and the support body comprises two or more
19 support
body segments. The three or more inner sleeve segments are retained
about the tubular by the two of more support body segments. The two or more
21 support body segments are retained about the inner sleeve by the end
collars.
22 In
another embodiment, the inner sleeve comprises six arcuate inner
23 sleeve
segments spaced at about 60 degrees and the support body comprises two
8
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1 semi-circular support body segments forming six windows. The six inner
sleeve
2 segments are retained about the tubular by the two support body segments.
The
3 two support body segments are retained about the inner sleeve by the end
collars.
4 According to one aspect of this disclosure, there is disclosed a
system
for drilling an openhole section from cased wellbore section. A drill string
comprises
6 resilient protrusion centralizer(s) on an uphole, cased section, and hard
protrusion
7 centralizer(s) on a downhole, uncased section.
8 In embodiments, use of resilient protrusion centralizer(s) and
hard
9 protrusion centralizer(s) may be adjusted during drill runs of the drill
string.
For example, when drilling the vertical portion of a horizontal wellbore,
11 no centralizer is used. When the drilling transits to horizontal
drilling, and the drilled
12 wellbore portion is cased, the drill string trips out, and is fit with
resilient protrusion
13 centralizer(s), for the casing portion, and hard protrusion
centralizer(s) downhole to
14 the resilient protrusion centralizer(s), for the openhole or uncased
portion. The drill
string may trip out a plurality of times during drilling operation, and in at
least some
16 drill string trip-out, at least some resilient protrusion centralizer(s)
may be replaced
17 with hard protrusion centralizer(s).
18 According to one aspect of this disclosure, there is disclosed
three
19 types of centralizers, including a resilient protrusion centralizer
having one or more
resilient protrusions each having a resilient surface, a hard protrusion
centralizer
21 having one or more hard protrusions each having a hard or stiff surface,
and a
22 centralizer having both resilient and hard protrusions (denoted as
resilient/hard
23 protrusion centralizer). In use, a drill string may be fit with all, or
any two types of,
9
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1 the three types of centralizers such that, except for a transitional
wellbore portion
2 between the casing portion and uncased or openhole portion thereof, the
casing
3 portion is faced with resilient protrusion surface(s), and the openhole
portion is
4 faced with hard protrusion surface(s). In the transitional portion, which
may
comprise a portion of casing uphole and a portion of uncased wellbore
downhole,
6 one may use centralizer(s) having resilient surface(s), being resilient
protrusion
7 centralizer(s) and/or resilient/hard protrusion centralizer(s). The
centralizers in the
8 transitional portion, when entering the openhole portion, face wear to
the resilient
9 protrusion(s). If resilient protrusion centralizer(s) are used, the
resilient protrusion
centralizer(s) may be worn out or damaged, and later replaced when the drill
string
11 is pulled out of hole for service. If resilient/hard protrusion
centralizer(s) are used,
12 the resilient protrusion(s) may be worn out, exposing hard protrusion(s)
for
13 contacting the wall of the uncased wellbore.
14 According to one aspect of this disclosure, there is disclosed a
method
of drilling a wellbore using a drill string having centralizer(s) having
resilient
16 protrusion surface(s) in an uphole, casing portion of a wellbore, and
having
17 centralizer(s) having hard protrusion surface(s) in a downhole, uncased
portion of
18 the wellbore.
19 In one embodiment, all centralizers are initially those having
resilient
protrusion surface(s). At each of at least some of drill string tripping out,
one or
21 more centralizers at a downhole side of the drill string are replaced
with those
22 having hard protrusion surface(s). Centralizers having resilient
protrusion surface(s)
23 are fit to an uphole side of the drill string as needed.
CA 02929318 2016-05-09
1 In
another embodiment, the drill string in an uphole, casing portion is
2 fit
with centralizer(s) having resilient protrusion surface(s). The drill string
in a
3
downhole, uncased portion is fit with centralizer(s) having hard protrusion
surface(s).
4 The
drill string in a transition portion between the uphole, casing portion and
the
downhole, uncased portion is fit with resilient/hard protrusion
centralizer(s).
6 In
another embodiment, the drill string is fit with resilient/hard
7
protrusion centralizer(s) only. In the casing portion of a wellbore, the
resilient
8
surface(s) of the centralizer(s) protect the casing from damage. The resilient
9
surface(s) of the centralizer(s) moving into the uncased portion of the
wellbore may
be worn out, and expose the hard surface(s).
11 In
practice, the Inner Diameter (ID) of the casing is usually slightly
12 larger
than that of the uncased wellbore portion. According to one aspect of this
13
disclosure, the resilient protrusion(s) are adapted to (but slightly smaller
than) the
14 Inner
Diameter (ID) of the casing, and the hard protrusion(s) are adapted to (but
slightly smaller than) that of the uncased wellbore portion.
16
According to one aspect of this disclosure, there is disclosed
17
centralizer for installing about a tubular. The centralizer comprises: a
resilient inner
18 sleeve
for circumferentially about the tubular, the inner sleeves forming opposing
19 axial
ends and a central bore adapted for slidably receiving the tubular; a tubular
outer support body about the inner sleeves, the support bodies forming
opposing
21 axial
ends and a body central bore for receiving the inner sleeve; one or more
22
protrusions radially extending from the outer support body for engaging the
wall of a
23
wellbore, and for spacing the tubular from the wellbore; and a pair of annular
end
11
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1 collars
configured to rotationally retain the tubular at opposing axial ends of the
2 support
body for preventing axial and radial movement of the support body
3 therebetween.
4 In some
embodiments, each of the one or more protrusions has a
resilient surface.
6 In some
embodiments, each inner sleeve segment further comprises
7 at
least one protruding member extending radially outwardly from an outer surface
8 thereof
for forming the one or more protrusions; and each support body segment
9 further
comprises at least one window formed therein for one of the at least one
protruding member to extend therethrough.
11 In some
embodiments, the protruding members and the windows are
12 formed generally longitudinal therealong.
13 In some
embodiments, each of the one or more protrusions has a
14 wear-resistant surface.
In some embodiments, at least a portion of the support body extends
16 radially outwardly, forming the one or more protrusions.
17 In some
embodiments, the one or more protrusions are further
18 covered by a layer of stiff material.
19 In some embodiments, the stiff material is tungsten carbide.
In some embodiments, at least one of the one or more protrusions is
21 covered by a resilient layer.
22 In some
embodiments, the support body is made of metal such as
23 steel.
12
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1 In some embodiments, the inner sleeve is made of a polymer.
2 In some embodiments, the inner sleeve is made of polyurethane.
3 According to one aspect of this disclosure, there is provided a
method
4 for drilling a wellbore. The method comprises: coupling one or more
centralizers of
claim 2 on a drill string, said drill string have a drilling bit at a distal
end; drilling a
6 portion of the wellbore using said drill string; pulling said drill
string out of hole;
7 casing at least a section of the drilled wellbore; replacing, from said
distal end, at
8 least one of the one or more centralizers with one or more above-
described
9 centralizers; and drilling a further portion of the wellbore using said
drill string.
According to one aspect of this disclosure, there is provided a system
11 for drilling an openhole wellbore from a cased wellbore. The system
comprises: a
12 drill string having an uphole portion and a downhole portion; a
plurality of resilient
13 centralizers having resilient protrusions, the resilient centralizers
fit to at least a
14 portion of the uphole portion; and a plurality of wear-resistant
centralizers having
hard protrusions, the wear resistant centralizers fit to at least a portion of
the
16 downhole portion; wherein, as the downhole portion of the drill string
advances in a
17 drilling run from the cased wellbore to drill in the openhole wellbore,
the wear-
18 resistant centralizers engage the openhole wellbore and the resilient
centralizers
19 engage the cased wellbore.
In some embodiments, the cased wellbore includes a deviated portion,
21 and wherein said at least a portion of the uphole portion fit with
resilient centralizers
22 is the deviated portion.
13
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1 In some
embodiments, the uphole portion remains in the cased
2 wellbore for the entire drilling run.
3 In some embodiments, the deviated portion is an angle build
portion.
4 In some
embodiments, the drill string further comprises a transition
portion intermediate the uphole and downhole portions, the transition portion
fit with
6 transition centralizers having a first resilient protrusions and second hard
7
protrusions, the first resilient protrusions having a greater radial extent
than the
8 second
hard protrusions, the downhole portion and a portion of the transition portion
9 of the
drill string advance from the cased portion to drill in the openhole wellbore,
some of the transition centralizers engage the open hole and some remain in
the
11 cased wellbore.
12 In some
embodiments, the resilient centralizers remain in the cased
13 wellbore during the drilling run.
14 In some
embodiments, the resilient centralizers are transition
centralizers, the first resilient protrusions engaging the cased wellbore; the
wear
16
resistant centralizers are transition centralizers, the first resilient
protrusions being
17 sacrificial for engaging the second hard protrusions with the openhole
wellbore.
18
According to one aspect of this disclosure, there is provided a method
19 of
drilling an open hole wellbore from a cased wellbore. The method comprises:
advancing a drill string along the wellbore in a drilling run from the cased
wellbore
21 and into
the openhole wellbore; centralizing at least a portion of an uphole portion of
22 the
drill string in the cased wellbore with resilient centralizers having
resilient
23
protrusions; and centralizing at least a portion of a downhole portion of the
drill
14
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1 string
in the openhole wellbore with wear resistant centralizers having hard
2 protrusions.
3 In some
embodiments, the cased wellbore includes a deviated
4 wellbore
further comprising centralizing the uphole portion of the drill string in the
deviated wellbore.
6 In some
embodiments, the method further comprises: fitting the
7 uphole
portion of the drill string with the resilient centralizers; fitting a
transition
8 portion
of the drill string, intermediate the uphole and downhole portions, with
9 transition centralizers having a first resilient protrusions and second hard
protrusions, the first resilient protrusions having a greater radial extent
than the
11 second
hard protrusions; advancing the downhole portion of the drill string in a
12 drilling
run along the openhole wellbore; centralizing the drill string in the openhole
13 wellbore
with the hard centralizers; advancing at least a portion of the transition
14 portion
of the drill string into the openhole wellbore; sizing the radial extent of
the
first resilient protrusions of the transition centralizers against the
openhole wellbore;
16 and
continuing to centralize the at least a portion of the transition portion in
the
17 openhole wellbore with the second hard protrusions.
18
According to one aspect of this disclosure, there is provided a dual-
19 gauge
centralizer for installing about a tubular. The centralizer comprises: a
resilient
inner sleeve fit circumferentially about the tubular, the inner sleeve forming
21 opposing
axial ends and a central bore adapted for slidably receiving the tubular; a
22 tubular
outer support body, the support body forming opposing axial ends and a
23 body
central bore for receiving the inner sleeve; a first set of protrusions
extending
CA 02929318 2016-05-09
1 radially from the outer support body to a first radial extent, the first
set of protrusions
2 being resilient and spacing the tubular from the wellbore; a second set
of
3 protrusions extending radially from the outer support body to a second
radial extent
4 smaller than the first radial extent, the second set of protrusions being
wear
resistant; and a pair of annular end collars configured to secure to the
tubular at
6 opposing axial ends of the support body for axially and radially
retaining the tubular
7 support body to the tubular.
8 In some embodiments, the first set and second sets of protrusions
are
9 circumferentially alternately distributed.
In some embodiments, at least a portion of the first set of protrusions
11 are wear-resistant protrusions covered by a resilient layer.
12 In some embodiments, at least a portion of the first set of
protrusions
13 are formed by extending the resilient inner sleeve radially outwardly
through ports
14 on the tubular outer support body.
According to one aspect of this disclosure, there is disclosed a method
16 of drilling a wellbore using a drill string having centralizers. The
wellbore comprises
17 an uphole, cased portion and a downhole, uncased portion. Centralizer(s)
having
18 resilient protrusion surface(s) are used for contacting the casing of
the cased
19 portion for centralizing the drill string therein, and centralizer(s)
having hard
protrusion surface(s) are used for contacting the wall of the uncased portion
for
21 centralizing the drill string therein.
22 In some embodiments, the resilient protrusion surface(s) may be
23 sacrificed to expose hard protrusion surface(s).
16
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1 In
particular, a centralizer may comprise resilient protrusion surface(s)
2 and hard
protrusion surface(s) covered thereunder. In use, the resilient protrusion
3
surface(s) may be worn out or sacrificed to activate hard protrusion
surface(s)
4 covered thereunder.
Alternatively, a centralizer may comprise one or more protrusions with
6
resilient protrusion surface(s) and one or more protrusions with hard
protrusion
7
surface(s). The protrusions with resilient protrusion surface(s) have greater
radial
8 extent
than those with hard protrusion surface(s). In use, the resilient protrusion
9
surface(s) may be worn out or sacrificed to reduce the radial extent thereof,
and
activate hard protrusion surface(s).
11
12 BRIEF DESCRIPTION OF DRAWINGS
13 Figure 1
is a schematic side view of a wellbore during a drilling
14
operation using centralizers, bent sub, and a drilling bit and a mud motor at
a distal
end thereof, the drilling operation continuing out of the cased wellbore
portion and
16 into an
openhole horizontal section; the drill string fit with resilient-protrusion
and
17 hard-protrusion centralizers;
18 Figure
2A is a perspective view of a resilient-protrusion centralizer
19
according to an embodiment disclosed herein and shown installed on a section
of
tubular;
21 Figure
2B is a side view of the resilient-protrusion centralizer of
22 Fig. 2A;
17
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1 Figure
20 is a side cross-sectional view of the resilient-protrusion
2 centralizer of Fig. 2A along line X-X;
3 Figure
3A is a perspective side view of six inner sleeve segments of
4 the
resilient-protrusion centralizer of Fig. 2A, each inner sleeve segment having
one
protruding member for a total of six when assembled;
6 Figure
3B is a perspective side view of two semi-circular support body
7
segments of the resilient-protrusion centralizer of Fig. 2A, each support body
8 segment
having three windows for receiving the protruding members of three inner
9 sleeve segments when assembled;
Figure 30 is a perspective side view of two of four inner sleeve
11
segments arranged on a tubular of the resilient-protrusion centralizer of Fig.
2A,
12 each
inner sleeve segment having one and one-half protruding members for a total
13 of six when assembled;
14 Figure
3D is a perspective side view of a half section of each of two of
semi-circular support body segments of the resilient-protrusion centralizer of
Fig. 2A,
16 each
support body having three windows for receiving combined three protruding
17 members from two inner sleeve segments of Fig. 3A;
18 Figure
4A is a perspective exploded view of two semi-circular support
19 body
segments each for installation over two inner sleeve segments of the resilient-
protrusion centralizer of Fig. 2A, each inner sleeve segment having one and
one-
21 half protruding members;
22 Figure
4B is a perspective view of one semi-circular support body
23 segment
for three protruding members and having two inner sleeve segments fit
18
CA 02929318 2016-05-09
1 thereto and one of the inner sleeve segments shown displaced or removed
to the
2 side to illustrate its corresponding remaining window in the support body
segment;
3 Figure 5 is a perspective side cross-sectional view of an annular
end
4 collar of the resilient-protrusion centralizer of Fig. 2A;
Figure 6 is a perspective, longitudinal view of the resilient-protrusion
6 centralizer of Fig. 2A, sectioned along the tubular axis, one semi-
circular support
7 body and one end collar removed for illustrating the inner sleeve,
support body and
8 end collar interfaces;
9 Figure 7 is a perspective, longitudinal view of the resilient-
protrusion
centralizer of Fig. 2A, sectioned along the tubular axis;
11 Figure 8 is a perspective side cross-sectional view of one half of
the
12 end collar of Fig. 5 with one support body segment supported therein;
13 Figures 9A and 9B are cross-sectional views along line B-B of Fig.
7,
14 more particularly, Fig. 9A shows the tubular supported in the inner
sleeve of the
resilient-protrusion centralizer, and Fig. 9B is shown absent the tubular for
16 illustrating the interface of the inner sleeve and support body in the
end collar;
17 Figure 10 is a perspective view of another embodiment of a
resilient-
18 protrusion centralizer and having one or more tubular resilient inner
sleeve sections
19 arranged between the support body and the tubular, each resilient inner
sleeve
section having resilient protrusions extending from the inner sleeve and
through
21 ports or windows formed in the outer support body;
22 Figure 11 is a side cross-sectional view of the centralizer of
Fig. 10
23 along line X-X;
19
CA 02929318 2016-05-09
1 Figure
12 is a cross-sectional view of one embodiment of a hard-
2 protrusion centralizer, shown installed on a section of tubular, and
having a resilient
3 inner sleeve extending beneath the outer support body and contour-fitting
thereto;
4 Figure
13 is a cross-sectional view of another embodiment of a hard-
protrusion centralizer having a resilient inner sleeve extending beneath the
outer
6 support body, an annular gap formed between the sleeve and support body;
7 Figure
14 is a cross-sectional view of another embodiment of a hard-
8 protrusion centralizer having a resilient inner sleeve extending beneath
the outer
9 support body and contour-fitting thereto, the hard protrusion portion of
the support
body also being hard-faced;
11 Figure
15 is a cross-sectional view of another embodiment of a hard-
12 protrusion centralizer having a two part, resilient inner sleeve
extending partially
13 beneath each end of the outer support body, an annular gap formed
between the
14 two sleeves and between the tubular and the support body;
Figures 16A to 160 illustrate a drilling operation using centralizers,
16 bent sub, and a drilling bit and a mud motor at a distal end thereof,
the drilling
17 operation continuing out of the cased wellbore portion and into an
openhole
18 horizontal section; in particular,
19 Figure
16A shows the drill string fit with resilient-protrusion
centralizers, some of which have moved into the openhole horizontal section;
21 Figure
16B shows the drill string having been tripped out for bit
22 maintenance and a centralizer change; and
CA 02929318 2016-05-09
1 Figure
16C shows the drilling operation continuing to extend
2 the
openhole portion, the string fit with a combination of resilient-protrusion
and
3 hard-
protrusion centralizers, the distal end of the string in the openhole fit
primarily
4 with
hard-protrusion centralizers and the drill string remaining in the cased
portion of
the wellbore fit with resilient-protrusion centralizers;
6 Figure
17A is a perspective view of a tubular centralizer having both
7
resilient and hard protrusions, and shown installed on a section of tubular,
8 according to an alternative embodiment;
9 Figure
17B is a side cross-sectional view of the centralizer of Fig. 17A
along line X-X;
11 Figure
18A is a perspective view of a tubular centralizer having both
12
resilient and hard protrusions, and shown installed on a section of tubular,
13 according to an alternative embodiment;
14 Figure
18B is a cross-sectional view of the centralizer of Fig. 18A
along line Y-Y;
16 Figure
19A is a perspective view of a tubular centralizer having both
17
resilient and hard protrusions, and shown installed on a section of tubular,
18 according to an alternative embodiment;
19 Figure
19B is a cross-sectional view of the centralizer of Fig. 18A
along line Y-Y;
21 Figure
20 shows a drilling operation using resilient/hard protrusion
22
centralizers of Figs. 17A and 17B, and/or Figs. 18A and 18B, a mud motor and
bent
21
CA 02929318 2016-05-09
1 sub, the drilling operation continuing out of the cased wellbore portion
and into an
2 openhole horizontal section, according to an alternative embodiment;
3 Figure 21 shows a drilling operation using resilient/hard
protrusion
4 centralizers of Figs. 17A and 17B, and/or Figs. 18A and 18B, a mud motor
and bent
sub, the drilling operation continuing out of the cased wellbore portion and
into an
6 openhole horizontal section, according to another embodiment;
7 Figure 22 shows a drilling operation when the drill string is
buckled
8 due to the uphole compression forces from the drill bit and the downhole
9 compression force from the drill rig.
11 DETAILED DESCRIPTION
12 The hard-protrusion and resilient-protrusion centralizer
embodiments
13 herein are an assembly of parts which result in a rugged construction
with the ability
14 to assemble loose shell components that do not have hinges, pins or
bands to hold
them together. The tubular string is used as one of the major structural
components
16 in the assembly.
17 Generally, embodiments of the centralizers disclosed herein
18 implement circumferential segments of a resilient inner sleeve that are
assembled
19 about and bear against the tubular drill string. The inner sleeve
segments are
retained to the tubular by circumferential segments of an outer support body.
The
21 inner sleeve and support body segments are retained to the tubular by
end collars
22 that overlap uphole and downhole overlapping ends of the inner sleeves
and
23 support body segments. The segments of the inner sleeve and the support
body are
22
CA 02929318 2016-05-09
1 assembled about the tubular in their unconnected form and secured thereto
using
2 annular end collars for preventing axial and radial movement of these
segments.
3 Accordingly the centralizers are installed about a joint of
tubular within
4 a wellbore. The centralizer comprises a resilient inner sleeve having a
central bore
formed therethrough for receiving the tubular therein and an outer surface.
The
6 centralizer further comprises a tubular outer support body having
opposing end
7 portions and a central bore formed therethrough for receiving the inner
sleeve's
8 outer surface. Three or more protruding members are spaced
circumferentially
9 about the centralizer and extend radially outwardly for spacing the
tubular from the
wellbore. The inner sleeve extends longitudinally beneath the support body.
The
11 centralizer further comprises a pair of annular end collars for
retaining the support
12 body and inner sleeve in the radial direction about the tubular and
axially thereto.
13 Each end collar has a collar bore for securing to the tubular and for
securing to an
14 opposing end portion of the support body.
In an embodiment, the three or more protruding members extend
16 radially outwardly from the support body. The inner sleeve can extend
contiguously
17 under the support body between the end collars. The inner sleeve can
further
18 comprise three or more protruding resilient members corresponding with
the three
19 or more protruding members of the support body, providing radial support
therefor.
Each of the support body's protruding members have a radial tip for engaging
the
21 wellbore, each tip further comprising hard-facing thereon.
22 In another embodiment, the three or more protruding members are
23 resilient members contiguous with each other and extending radially
outwardly from
23
CA 02929318 2016-05-09
1 the inner sleeve. Further, the support body has windows formed therein
which
2 correspond with the protruding members. When the inner sleeve is retained
3 between the support body and the tubular, the protruding members project
through
4 the windows with the balance of the inner sleeve extending longitudinally
beneath
the support body.
6 In embodiments, the inner sleeve comprises two or more
7 circumferentially arcuate inner sleeve segments retained about the
tubular by the
8 support body. In another embodiment, the inner sleeve comprises three or
more
9 arcuate inner sleeve segments retained about the tubular by the support
body.
Further, the support body can be provided as two or more support body segments
11 and the two or more support body segments are retained about the inner
sleeve by
12 the end collars.
13 As will be described in more detail below, the protruding members
for
14 engaging the wall of the wellbore may be resilient protrusions or hard
protrusions in
various embodiments. Generally the inner sleeve and support body approach is
16 applicable for both hard and resilient implementations.
17 Horizontal drilling has placed greater demands on centralizers
than
18 ever before. Centralizers support a larger share of the drill string
weight along the
19 horizontal portions while also being subjected to the forces during slip-
slide drilling
techniques. Herein, two forms of robust centralizers are disclosed, both of
which
21 utilize a metal outer support body, a resilient inner sleeve and
retaining end collars
22 according to embodiments described herein. As shown in Figs. 1A to 1C,
the form
23 of centralizer is matched with the wellbore environment, having a metal
or hard-
24
CA 02929318 2016-05-09
1 faced metal protrusions for openhole wellbore (Figs. 2 to 5), and/or
having resilient
2 protrusions for cased wellbore (Figs. 6, 7 and 8A-15B).
3 In the horizontal well context, the openhole wellbore is typically
the
4 horizontal portion extending out of the cased portion from the heel to
the end,
usually called the toe section. Openhole is much more abrasive and destructive
to
6 centralizers than is inside the smooth casing. Centralizers quickly
degrade when
7 they exit the casing and end up in openhole.
8
9 Drill String with Resilient-Protrusion and Hard-Protrusion Centralizers
With reference to Fig. 1, a wellbore 100 in drilling operation using a
11 drill string 106 having one or more drilling pipes 107 is shown. Similar
to the
12 wellbores known in the art, the wellbore 100 starts from a vertical
wellbore portion
13 and transits to a horizontal portion via a so-called "heel", also
denoted as a deviated
14 portion or deviated wellbore hereinafter. In some embodiments, the
deviated portion
or deviated wellbore is an angle build portion, and may also more generally
refer to
16 a wellbore section that changes direction.
17 In this embodiment, the wellbore 100 comprises a casing portion
102,
18 also denoted as cased portion or cased wellbore hereinafter. The casing
portion
19 102 in this embodiment includes the heel or deviated portion. The
wellbore 100 also
comprises an openhole portion 104, also denoted as uncased portion or openhole
21 wellbore hereinafter.
22 Correspondingly, the drill string 106 comprises one or more
resilient-
23 protrusion centralizers 110, also denoted as resilient centralizers
hereinafter,
CA 02929318 2016-05-09
1 spaced therealong in the cased portion 102 to centralize the drill pipe
107 therein,
2 and in particular to centralize the drill pipe 107 in the deviated
portion. The drill
3 string 106 also comprises one or more hard-protrusion centralizers 111,
also
4 denoted as hard centralizers or wear-resistant centralizers hereinafter,
spaced
therealong in the openhole portion 104 to centralize the drill pipe 107
therein.
6 Herein, the resilient-protrusion centralizers 110 comprise resilient
protrusions each
7 having a resilient surface for engaging the wall of the wellbore 100, for
protecting
8 the casing or liner of the cased portion 102 from wearing as the drill
string advances
9 therethrough. The hard-protrusion centralizers 111 comprise stiff or wear-
resistant
protrusions each having a stiff or wear-resistant surface for engaging the
wall of the
11 wellbore 100. The hard-protrusion centralizers 111 are more suitable for
adapting to
12 the abrasive wall of the openhole wellbore portion 104.
13 During drilling operation, the drill pipe 107 rotates inside the
14 centralizers 110 and 111. On the other hand, the centralizers 110 and
110 typically
are not rotating against the casing 102 and uncased well bore 104. However,
with
16 the progress of the drilling operation, the centralizers 110 and 111
slide downhole
17 with the advancing of the drilling pipe 107. The centralizers 110 and
111 slide
18 uphole when the drill string 106 is pull out of hole for service.
19
Resilient-Protrusion Centralizers
21 Figs. 2A to 2C show greater details of the resilient-protrusion
22 centralizer 110 according to one embodiment. As shown in Fig. 2A, a
centralizer
23 110 is shown installed on a section or joint of a tubular 112 such as
the drill pipe
26
CA 02929318 2016-05-09
1 107, which may be a part of the drill string 106. The centralizer 110
comprises a
2 resilient inner sleeve 114 for supporting the tubular 112 from the
wellbore such as
3 casing or other tubular string. The centralizer 110 further comprises a
tubular outer
4 support body 116, sandwiching the inner sleeve 114 between the support
body 116
and the tubular 112. Despite being fit with an outer support body 116, the
inner
6 sleeve 114 protrudes therethrough, forming a plurality of
circumferentially spaced
7 protruding members 120 for engaging the wellbore (not shown), and
centralizing
8 and spacing both the tubular 112 and the support body 116 therefrom.
Preferably,
9 the inner sleeve 114 is made of a polymer such as polyurethane for
minimizing
damage to the inside of the casing or wellbore on one side and particularly to
the
11 tubular on the other side. In this embodiment, inner sleeve 114 serves
as a
12 sacrificial component for periodic replacement.
13 With reference to Figs. 2B and 2C, the inner sleeve 114 comprises
14 three or more circumferentially spaced protruding members 120 formed
generally
longitudinally along the inner sleeve between opposing ends 122, 122 of the
inner
16 sleeve 114.
17 The support body 116 is more robust, generally being manufactured
of
18 metal such as steel. Thus, both the tubular 112 and the wellbore side
walls are
19 contacted by a softer resilient material, and contact with the hard
support body 116
is avoided or at least minimized. The support body 116 retains the inner
sleeve 114
21 in the radial direction and circumferentially about the tubular 112. The
hard support
22 body 116 further also protects the softer inner sleeve 114. The inner
sleeve 114 and
23 the support body 116 are retained both axially along and radially about
the tubular
27
CA 02929318 2016-05-09
1 112 using a pair of bookend end collars 118, 118. The end collars 118,
118, in
2 addition to retaining the inner sleeve 114 and support body 116 on the
tubular 112,
3 also axially position the support body 116 and the inner sleeve 114 along
the
4 tubular 112.
The disclosed inner sleeve 114 may be of a single piece construction
6 with a split for resilient installation about the tubular, or may
comprise multiple
7 segments that cooperate as a circumferential array about the tubular 112.
For ease
8 of assembly about the tubular 112, the inner sleeve 114 and the support
body 116
9 are formed of at least two segments. The description and drawings
describe and
illustrate the inner sleeve 114 and support body 116 as comprising at least
two
11 segments, however, it is to be understood that the disclosure is not so
limited.
12 With reference to Fig. 3A, an inner sleeve 114 formed of six
arcuate
13 inner sleeve segments 114A spaced at about 60 degrees is illustrated.
Each inner
14 sleeve segment 114A comprises at least one of the protruding members
120. The
protruding member 120 extends radially outwardly from an outer surface 124 of
the
16 inner sleeve segment 114A. The multiple inner sleeve segments 114A are
17 arranged circumferentially in a radial array about the tubular 112 and
abut each
18 other along longitudinal edges 115 to form the inner sleeve 114. The
inner sleeve
19 114 forms a central bore 126. The tubular 112 is longitudinally
supported in the
central bore 126. The inner sleeve segments 114A and the protruding members
21 120 thereon are configured such that, when assembled, protruding members
120
22 are evenly and circumferentially spaced about the inner sleeve 114 and
tubular 112.
28
CA 02929318 2016-05-09
1 Fig. 38
illustrates a support body 116 generally formed of two or more
2 support
body segments 116A for ease of installation. In one embodiment, the
3 support
body 116 is formed of two, semi-circular support body segments 116A,
4 116A.
As shown, each support body segment 116A is configured to house three
inner sleeve segments 114A, 114A, 114A of Fig. 3A. Accordingly, each support
6 body
segment 116A comprises three windows 128 formed generally lengthwise
7 between
opposing end portions 130, 130 of the support body 116. When arranged
8
circumferentially, the two support body segments abut each other along
longitudinal
9 edges
117 forming a central bore 132. The support body's bore 132 retains the
outer surface 124 of the inner sleeve 114. Each window 128 is supported within
a
11
longitudinal buttress 134 about a perimeter of the window 128. The support
body
12
segments 116A, the windows 128 and the buttresses 134 are configured such that
13 when
the support body segments 116A are arranged circumferentially, the windows
14 128 and
the buttresses 134 are evenly spaced about the support body 116,
corresponding to the arrangement of the protruding members 120.
16 The
protruding members 120 and the windows 128 are
17
complementary to each other and align during assembly. The windows 128 are
18 sized and shaped to receive the protruding members 120 during assembly.
19
Depending upon the number of inner sleeve segments, and protruding
members per inner sleeve segment 114A, and the number of support body
21
segments 116A and corresponding windows 128 formed therein, the inner sleeve
22
segments 114A may need to installed into the support body 116 before assembly
to
23 the
tubular 112 or, in other instances, typically with a large number of segments
29
CA 02929318 2016-05-09
1 114A, 116A, one can assemble the support body segments to inner sleeve
2 segments already arranged about the tubular 112. The resilience of the
inner
3 sleeve can aid in manipulating the protruding members 120 through
corresponding
4 windows 128.
As shown in Fig. 30, a tubular 112 is shown fit with two of four inner
6 sleeve segments 114A. In Fig. 3D, two quadrants of two support body
segments
7 116A are shown in corresponding orientation for installation to the inner
sleeve
8 segments 114A.
9 With reference to Fig. 4A, the arrangement of Figs. 3C and 3D is
in
relative location such as for assembly. In this arrangement it is likely that
two inner
11 sleeve segments 114A, 114A, having one and one-half protruding members
120 per
12 segment would need to be pre-installed into the three-window 128 support
body
13 segments 116A. A first semi-circular support body segment 116A is
aligned with
14 two 90 degrees inner sleeve segments 114A, 114A (only one of two are
shown in
this section) and a second semi-circular support body segment 116A is aligned
with
16 another two 90 degrees inner sleeve segments 114A, 114A.
17 With reference to Fig. 4B, one semi-circular support body segment
18 116A is preloaded with two of three inner sleeve segments 114A, the
protruding
19 members 120 extending through their respective windows 128. This
embodiment is
similar to that shown in Figs. 3A and 3B. One inner sleeve segment 114A is
shown
21 displaced with installation arrows indicating its form of installation
with the
22 protruding member 120 extending into the remaining available window 128.
CA 02929318 2016-05-09
1 Having
reference to Fig. 5, each annular bookend end collar 118 is
2 formed
as two semi-circular clamshell segments or halves 118A and 118B which
3 are
connected together at connecting edges 118C. When coupled, the end caps
4 118, 118
retain both the support body 116 and inner sleeve 114 to the tubular 112.
The end caps are assembled using fasteners such as at least two high tensile
steel
6 bolts or
cap screws 136, at opposing tangential connectors, spanning across the
=
7
connecting edge 118C. This is similar to the connection arrangement discussed
in
8 the
prior art. Generally, the fasteners 136 extend transverse to the longitudinal
axis
9 of the
centralizer 110, each bolt 136 being installed in an opposing direction to a
longitudinally adjacent fastener 136 through a corresponding bolt hole 137. As
one
11 of skill
in the art will appreciate, the more fasteners 136 which can be used the
12 stronger
the connection. The number of fasteners 136 which can be used is
13
generally limited by the axial length of the end collars 118 and practically,
by the
14 overall axial length of the support body 116.
Each end collar 118 comprises a collar bore 138 formed longitudinally
16 or
lengthwise therethrough. The bore 138 has a first diameter section 140
17
corresponding to a diameter of the ends 130, 130 of the support body 116, and
a
18 second
diameter section 142 corresponding to a diameter of the tubular 112. The
19 step in
diameter sections 140, 142 forms a stop shoulder 141 and the first diameter
section 140 forms an annular overlapping portion 143. The second diameter
section
21 is a clamping bore portion and is smaller than the first diameter
section.
22 Turning
to Figs. 6 and 7, the centralizer 110 is assembled around the
23 tubular
112 as follows: the inner sleeve 114 is arranged circumferentially around the
31
CA 02929318 2016-05-09
1 tubular 112 and the support body segments 116A are circumferentially
arranged
2 around the inner sleeve 114, the protruding members 120 being aligned and
fit to
3 the corresponding windows. The protruding members 120 are received within
the
4 windows 128 and project radially outwardly therethrough. The various
components
are held in place by the bookend end collars 118, 118. As also shown in
isolation in
6 Fig. 8, the annular overlapping portions 143, 143 of the end collars 118,
118 are
7 axially located about the respective downhole and uphole ends 130, 130 of
the
8 support body 116. As shown in this embodiment, and illustrated where the
9 opposing end collar 118 has been omitted in Fig. 6 for viewing the ends
122, 130,
the inner sleeve's ends 122, 122 happen to be coincident with the ends 130,
130 of
11 the support body 116.
12 Also shown in Figs. 8 to 9B, when the second diameter portion or
13 clamping bore 142 of the end collars 118 are secured to the tubular 112,
the end
14 collars 118, 118 retain the support body 116 and the inner sleeve 114
about the
tubular 112. The opposing ends 122, 122 and end portions 130, 130 of the inner
16 sleeve 114 and the support body 116, respectively are received within
the first
17 diameter section 140 of the end collar 118, the annular overlapping
portion 143
18 radially retaining the support body 116 against the inner sleeve 114
which is
19 retained against the tubular 112. The ends 130, 130 of the support body
116 abut
the respective shoulders 141, 141 for fixing the axial position of the inner
sleeve 114
21 and support body 116. This enables the inner sleeve 114 and the support
body 116
22 to be circumferentially supported around the tubular 112. The stop
shoulders 141,
23 141 also axially delimit the support body 116 against movement along the
tubular
32
CA 02929318 2016-05-09
1 112. Depending on the clearances between the support body 116 and the end
collar
2 116 and between the inner sleeve and tubular 112, the inner sleeve 114
and
3 support body 116 could rotate about the tubular 112. The second diameter
section
4 142 of the end collar 118 grips the tubular 112 for positioning and
fixing the support
body 116 and the inner sleeve 114 on the tubular 112.
6 In order to minimize interference or catching with casing collars
and
7 other discontinuities during installation and use, the leading and
trailing longitudinal
8 edges of all components can be chamfered including the end collars 118,
the
9 support body buttresses 134, and the protruding member 120.
Once assembled, the protruding members 120 on the inner sleeve
11 extend beyond the support body 116 to a radial extent greater than that
of the end
12 collars 118, 118 for spacing the tubular 112, the support body 116 and
the end
13 collars 118, 118 from the walls of the casing or wellbore. This also
minimizes
14 contact between the support body 116 and the wellbore or casing
sidewalls. Due to
the unique construction of the inner sleeve 114 and the support body 116, no
16 connectors are required to retain the inner sleeve 114 and the support
body 116
17 together. Engagement of the protruding members 120 with the windows 128
retains
18 the inner sleeve 114 within the support body 116. The only connectors
required are
19 associated with the end collars 118, 118 for retaining and positioning
the inner
sleeve 114 and the outer body 116 about the tubular 112. The unique
construction
21 of the annular end collars 118, 118 enables the end collars 118 to be
secured about
22 the support body 116 using minimal connectors. The configuration of the
centralizer
33
CA 02929318 2016-05-09
1 110 is
therefore less complicated, having minimized the number of connectors,
2 therefore minimizing the risk of failure and reducing the cost and
assembly time.
3 As the
only contact between the centralizer 110 and casing or
4 wellbore
walls is the protruding members 120, the inner sleeve 114 is prone to wear
and tear and is sacrificial. Multi-segment construction of the inner sleeve
114
6 enables
replacement of only the inner sleeve segment 114A with worn protruding
7 members.
Only those individual inner sleeve segments 114A whose one or more
8
protruding members 120 are worn sufficiently to warrant replacement are need
be
9 replaced
at any one time however conservative practices may dictate replacing all
at once. The method for replacement of inner sleeve segments 114A with worn
11
protruding members 120 typically comprises disengaging at least one of the
annular
12 end
collars 118 and removing one or more of the support body segments 116A for
13
accessing the inner sleeve segments 114A. The inner sleeve segments with worn
14
protruding members 120 are then removed and replaced with replacement inner
sleeve segments. The replacement inner sleeve segments and the support body
16 segments
are then re-installed about the tubular and the disengaged annular end
17 collar
is secured to the tubular and about the opposing end portion of the support
18 body.
19 Figs. 10
and 11 show a resilient-protrusion centralizer according to
another alternative embodiment. As shown, the outer support body 116 comprises
21 a
plurality of windows or ports distributed circumferentially and axially
thereon.
22
Correspondingly, a plurality of resilient protrusions 120 extends from the
inner
34
CA 02929318 2016-05-09
1 sleeve 114 through the circumferentially and axially distributed windows
or ports of
2 the outer support body 116.
3
4 Hard-Protrusion Centralizers
Fig. 12 shows a hard-protrusion centralizer 111 according to one
6 embodiment. Similar to the above-described resilient-protrusion
centralizer 110, the
7 hard-protrusion centralizer 111 is installed on a section or joint of a
tubular 112 such
8 as a drill pipe, and comprises a resilient inner sleeve 114 sandwiched
between an
9 outer supporting body 116 and the tubular 112. The outer support body 116
is
generally manufactured of metal such as steel. A portion of the supporting
body 116
11 extends radially outwardly, forming a circumferentially continuous, hard
protrusion
12 120, having a radial tip for engaging the wellbore. Other parts and
components of
13 the hard-protrusion centralizer 111 are generally the same as those of
the above-
14 described, resilient-protrusion centralizer 110, and are therefore
omitted.
In this embodiment, the inner sleeve 114 also extends beneath the
16 outer support body 116, and is contour-fitting to the outer support body
116 for
17 support of the protrusion 120.
18 In another embodiment, the hard protrusion 120 is not
19 circumferentially continuous. Rather, the hard-protrusion centralizer 111
may
comprise a plurality of circumferentially spaced hard protrusions.
21 In another embodiment, the hard-protrusion centralizer 111 may
22 comprise a plurality of axially spaced hard protrusions.
CA 02929318 2016-05-09
1 In
another embodiment, the hard-protrusion centralizer 111 may
2 comprise a plurality of circumferentially and axially spaced hard
protrusions.
3 Fig. 13
shows a hard-protrusion centralizer 111 according to another
4
embodiment. The hard-protrusion centralizer 111 of Fig. 13 is similar to that
of Fig.
12, except that, in this embodiment, the resilient inner sleeve 114 is a
cylindrical
6 tubular
extending axially beneath the outer support body 116. An annular gap 202
7 is thus
formed between the sleeve 114 and support body 116, the support body 116
8 having sufficient structure to be self-supporting under load.
9 Fig. 14
shows a hard-protrusion centralizer 111 according to another
embodiment. The hard-protrusion centralizer 111 of Fig. 14 is similar to that
of Fig.
11 13.
However, in this embodiment, at least one of the hard protrusion portions 120
is
12 further
hard-faced with stiff or wear-resistant material 204 such as tungsten carbide.
13 The
advantage of this embodiment is that the hard protrusion will last much longer
14 before the protrusion wears down.
Fig. 15 shows a hard-protrusion centralizer 111 according to yet
16 another
embodiment. In this embodiment, the hard-protrusion centralizer 111
17
comprises a two part, resilient inner sleeve 114 extending partially beneath
each
18 end of
the outer support body 116. The inner sleeve 114 is retained axially by
19
suitable means, such as by the bookend end collars 118, 118. An annular gap
202
is formed between the two sleeves 114, and between the tubular 112 and the
21 support
body 116. In this embodiment the inner sleeves might have to be attached
22 to the
outer sleeve segments by means of gluing or vulcanizing so that the inner
36
CA 02929318 2016-05-09
1 sleeves do not drift away from their intended (as shown) position in the
axial
2 direction.
3
4 Drilling Method Using Resilient-Protrusion and Hard-Protrusion
Centralizers
Figs. 16A to 160 illustrate a drilling method using resilient-protrusion
6 and hard-protrusion centralizers. As shown in Fig. 16A, one can drill
with resilient
7 centralizers 110 spaced along the drill string 106, to protect the cased
portion 102 of
8 the wellbore 100 at least until a portion of the horizontal portion is
drilled. The
9 resilient centralizers 110 are particularly important to minimize wear to
the casing as
the drill string 106 advances therethrough. The drilling continues out the end
of the
11 casing shoe 210 and into openhole 104, and some resilient-protrusion
centralizers
12 110 move into the openhole portion 104. As the resilient-protrusion
centralizers 110
13 are not optimal for openhole, some resilient-protrusion centralizers 110
exposed to
14 the openhole environment may be worn or damaged.
As shown in Fig. 16B, coincident with a bit change, the drill string 106
16 is tripped out. The worn or damaged resilient-protrusion centralizers
110 on the
17 downhole distal end of the drill string 106 are removed and replaced
with hard-
18 protrusion centralizers 111. In particular, a downhole length of the
drill string 106
19 that will be extended into the openhole 104 is determined and this
portion is fit with
the hard-protrusion centralizers 111. The balance of the drill string 106 that
will, for
21 the most part, remain in the existing casing 102 and is fit with the
resilient
22 centralizers 110. As shown in Fig. 160, the drill string 106 with both
resilient-
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CA 02929318 2016-05-09
1 protrusion and hard-protrusion centralizers 110 and 111 is then extended
into the
2 wellbore 100 to further drill the wellbore 100.
3 Of course, as the drill string 106 continues to drill forward,
some of the
4 resilient centralizers 110 in the casing 102 move from the casing 102
into the
openhole 104, and are then subject to wear and damage. During wellbore
drilling,
6 the above described procedure of pulling the drill string 106 out of hole
and
7 replacing resilient-protrusion centralizers 110 with hard-protrusion
centralizers along
8 a projected openhole portion of the drill string 106 may be repeated a
few times as
9 necessary or coordinated with other bottom hole assembly servicing.
With the above described drilling method (Figs. 16A to 16C), hard-
11 protrusion centralizers 111 are used on the portion of the drill string
106 that spends
12 most of its time in openhole 104, for combating centralizers wearing out
or damage,
13 and resilient protrusion centralizers 110 are used in the portion of the
drill string 106
14 that spends most of their time in the casing 102, for protecting the
casing 102.
Significant operational advantages are realized.
16
17 Centralizer with both Resilient and Hard Protrusions
18 Figs. 17A and 17B show a centralizer 220 having both resilient and
19 hard protrusions (also denoted as resilient/hard protrusion centralizer
or transition
centralizer hereinafter), according to an alternative embodiment. The
resilient/hard
21 protrusion centralizer 220 of Figs. 17A and 17B is similar to that of
Fig. 14. However,
22 in this embodiment, the hard protrusion(s) 120B is covered with an
outermost
23 resilient layer 222 to form resilient protrusion(s) 120A. Any suitable
means, such as
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CA 02929318 2016-05-09
1 screwing, coating, gluing, vulcanizing and the like, may be used to cover
the
2 outermost resilient layer 222 to the hard protrusion(s) 120B. For
example, the
3 outermost resilient layer 222 may be a resilient polyurethane coating
that is bonded
4 to the support body 116.
In above embodiment, all hard protrusions 120B are covered with an
6 outermost resilient layer 222. In an alternative embodiment, only some of
the hard
7 protrusions 120B are covered with an outermost resilient layer 222. For
example, as
8 shown in Figs. 18A and 18B, the resilient/hard protrusion centralizer 230
comprises
9 three resilient protrusions 120A and three hard protrusions 120B,
preferably
circumferentially alternately distributed. Protrusions 120A and 120B in this
example
11 are formed by the radially outwardly extended portions of the support
body 116.
12 However, the resilient protrusions 102A are covered by outermost
resilient layer 222,
13 and the hard protrusions 120B are hard-faced with stiff material 204.
14 In this example, the cased portion 102 has a slightly larger
diameter
than that of the openhole portion 104. Correspondingly, the resilient
protrusions
16 120A have a first radial extent slightly smaller than that of the cased
portion 102, i.e.,
17 the resilient protrusions 120A radially outwardly extending to about,
but slightly
18 smaller than, the inner surface of the casing 102. The hard protrusions
120B have a
19 second radial extent slightly smaller than that of the openhole portion
104, i.e., the
hard protrusions 120B radially outwardly extending to about, but slightly
smaller
21 than, the wall of the uncased wellbore 104. The first radial extent of
the resilient
22 protrusions 120A is greater than the second radial extent of the hard
protrusions
23 120B. The so formed centralizer is then a dual-gauge centralizer having
two
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CA 02929318 2016-05-09
1
centralizer diameters corresponding to the above-described first and second
2 diameters.
3 For
example, wellbore drilling in Canada commonly uses 7" Outer
4
Diameter (OD) casing to the 90-degree location (the "heel" of a horizontal
well,
where the wellbore is transiting from vertical to horizontal). A 7" casing
under a
6 typical
17 pounds per foot (ppf) pressure gives rise to a 6. 538" casing Inner
7 Diameter (ID).
8
Downhole to the 7" casing, a horizontal bore is then drilled with a
9 6.25"
drill bit, typically giving rise to an ID smaller than that of the 7" casing.
Generally, the ID of the openhole portion is slightly larger than the diameter
of the
11 drill
bit due to bit wobble and vibration, and is slightly smaller than the diameter
of
12 the
drill bit due to bit wearing. Often, a thick "filter cake" may develop on the
13
borehole wall of the openhole portion, which effectively makes the hole size
smaller.
14
Therefore, generally, the centralizers are designed to have ODs
smaller than the ID of the casing or openhole. In particular, centralizer
protrusions
16 having
resilient surfaces are designed to have an OD smaller than the ID of the
17 casing,
and centralizer protrusions having hard surfaces are designed to have an
18 OD smaller than the ID of the openhole.
19 For
example, in one embodiment, resilient protrusions 120A are
designed to have an OD of about 6.25", and hard protrusions 120B are designed
to
21 have an
OD of about 6.0" or about 6.1". In this embodiment, the resilient protrusions
22 120A
can fit in the uncased portion without being too tight, slowing wearing
thereto,
23 compared to the design of resilient protrusions having larger OD.
CA 02929318 2016-05-09
1 In
another embodiment as shown in Figs. 19A and 19B, the dual-
2 gauge,
resilient/hard protrusion centralizer 240 is the same as the dual-gauge,
3
resilient/hard protrusion centralizer 230 of Figs. 18A and 18B, except that,
in this
4
embodiment, the resilient protrusions 120A are formed by extending the
resilient
inner sleeve 114 out of respective windows of the support body 116. The hard
6 protrusions 120B are formed in a same manner as those of Figs. 18A and
18B.
7
Although now shown in the drawings, in one alternative embodiment,
8 a dual-
gauge, resilient/hard protrusion centralizer is similar to the centralizer 110
of
9 Figs.
10 and 11, except that some of the protrusions 120 are hard protrusions and
some others thereof are resilient protrusions (formed by the resilient sleeve
114, or
11 by covering hard protrusions with a resilient layer).
12 In an
embodiment as shown in Fig. 20, a drill string 106 may be
13
equipped with one or more resilient/hard protrusion centralizers 250A and 250B
14 spaced
axially therealong. In particular, all the resilient/hard protrusion
centralizers
250A and 250B are the resilient/hard protrusion centralizer(s) 220 of Figs.
17A and
16 17B,
the resilient/hard protrusion centralizer(s) 230 of Figs. 18A and 18B, the
17
resilient/hard protrusion centralizer(s) 240 of Figs. 19A and 19B, or a
combination
18 thereof.
19 During
drilling, the centralizers 250A in the casing portion 102 protect
the casing. With drilling advance, some centralizers 250A move into the
openhole
21 portion
104, and the outermost resilient layer 222 of the resilient protrusions 120A
22 may be
worn or damaged (such centralizers being denoted in Fig. 20 as 250B). The
23 radial
extent of the resilient protrusions 120A are then sized or sacrificed, such
that
41
CA 02929318 2016-05-09
1 the hard protrusion(s) 120B are then exposed, preventing the centralizers
250B
2 from being damaged. By using the resilient/hard protrusion centralizers
250A and
3 250B, there is no need to replace the centralizers in the openhole
portion 104
4 unless they are damaged.
In another embodiment as shown in Fig. 21, a drill string 106 may be
6 equipped with one or more centralizers 260A, 260B and 2600 spaced axially
7 therealong. In particular, centralizer(s) 260A are within the casing
portion 102 during
8 the entire drilling process, and therefore, may be any above-described
resilient
9 protrusion centralizer 110 or resilient/hard protrusion centralizer(s)
220, 230 and/or
240. The centralizer(s) 260B are within the openhole portion 104 during the
entire
11 drilling process, and therefore, may be any above-described hard
protrusion
12 centralizer 111 or resilient/hard protrusion centralizer(s) 220, 230
and/or 240.
13 The centralizer(s) 2600 are transition centralizer(s), which may
be any
14 above-described resilient/hard protrusion centralizer(s) 220, 230 and/or
240. The
transition centralizer(s) 2600 are initially within the casing portion 102.
With the
16 drilling progress, the centralizers 2600 are initially in the casing
portion 102,
17 protecting the casing. With drilling advance, some or all of
centralizers 2600 move
18 into the openhole portion 104, and the outermost resilient layer 222 may
be worn or
19 damaged. The hard protrusion(s) 120B are then exposed, preventing the
centralizers 2600 from being damaged. Consequently, there is no need to
replace
21 the centralizers in the openhole portion 104 unless they are damaged.
22 In practice, the drill string 106 is usually pulled out of hole
only for
23 important services such as replacing worn drilling bit, replacing failed
Measurement-
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CA 02929318 2016-05-09
1 while-
Drilling (MWD) tools, failed mud motor, or having reached the total depth
2
(meaning the drilling process being completed). However, replacing
centralizers is
3 usually
not considered an important service. Therefore, as the process shown in Fig.
4 19 or
20 does not need to replace the centralizers (from resilient protrusion
centralizers to hard protrusion centralizers or vice versa), it reduces the
risk of
6
damaging the casing, and the risk of damaging the drill string 106 or biasing
from
7 planned
drilling direction due to damaged centralizer(s), and saves time and
8 expense.
9 Rotary
steerable systems are recently used in more and more
applications of drilling horizontal wellbores. As is known in the art,
compared to
11
traditional drilling systems, rotary steerable systems can drill a much
straighter
12
wellbore, which is critical and required for drilling long horizontal wells,
such as
13 those
of one mile to two miles long. Longer horizontal wells generally provide
better
14 production and lower well cost per barrel produced.
However, as the drill pipe in a rotary steerable system rotates all the
16 time,
casing wear caused by centralizers in rotary steerable systems is a more
17 serious
issue than that in traditional drilling system. The centralizers disclosed
18 herein
are suitable for rotary steerable systems in reducing or preventing casing
19 wear, and in reducing or preventing centralizer damage.
As shown in Fig. 22, in wellbore drilling practice, a drill pipe 107 of the
21 drill
string 106 between drill pipe tool joints 302 may be buckled or warped due to
22 the
uphole compression forces 304 from the drill bit at the downhole side of the
drill
23 string
106, and the downhole compression force 306 from the drill rig at the uphole
43
CA 02929318 2016-05-09
1 side thereof. Traditionally, expensive, specially designed drill pipes
are used to
2 combat the buckling. However, the centralizers disclosed herein may be
used for
3 combating the buckling with lower cost.
4 In above embodiments, hard protrusions are formed by radially
outwardly extending the support body 116. In an alternative embodiment, hard
6 protrusions are formed separately from the support by 116, by using
suitable
7 material with sufficient stiffness.
8 In the embodiments of Figs. 17A to 19B, some resilient protrusions
9 are formed by covering a resilient layer onto respective hard
protrusions. In some
alternative embodiments, some resilient protrusions are formed by first
coating the
11 respective hard protrusions with stiff or wear-resistant material and
then covering
12 the respective coated hard protrusions with a resilient layer.
13 Although embodiments have been described above with reference to
14 the accompanying drawings, those of skill in the art will appreciate
that variations
and modifications may be made without departing from the scope thereof as
defined
16 by the appended claims.
17
44
